Oil well logging has been known for many years and provides an oil and gas well driller with information about the particular earth formation being drilled. In conventional oil well logging, after a well has been drilled, a probe known as a sonde is lowered into the borehole and used to determine some characteristic of the formations which the well has traversed. The probe is typically a hermetically sealed steel cylinder which hangs at the end of a long cable which gives mechanical support to the sonde and provides power to the instrumentation inside the sonde. The cable also provides communication channels for sending information up to the surface. It thus becomes possible to measure some parameter of the earth's formations as a function of depth, that is, while the sonde is being pulled uphole. Such “wireline” measurements are normally done in real time (however, these measurements are taken long after the actual drilling has taken place).
A wireline sonde usually transmits energy into the formation as well as a suitable receiver for detecting the same energy returning from the formation to provide acquisition of a parameter of interest. As is well known in this art, these parameters of interest include electrical resistivity, acoustic energy, or nuclear measurements which directly or indirectly give information on subsurface densities, reflectances, boundaries, fluids and lithologies among many others.
Examples of prior art wireline density devices are disclosed, for example, in U.S. Pat. No. 4,628,202 to Minette. Wireline formation evaluation tools (such as gamma ray density tools) have many drawbacks and disadvantages including loss of drilling time, the expense and delay involved in tripping the drillstring so as to enable the wireline to be lowered into the borehole and both the build up of a substantial mud cake and invasion of the formation by the drilling fluids during the time period between drilling and taking measurements. An improvement over these prior art techniques is the art of measurement-while-drilling (MWD) in which many of the characteristics of the formation are determined substantially contemporaneously with the drilling of the borehole.
Measurement-while-drilling (MWD) logging either partly or totally eliminates the necessity of interrupting the drilling operation to remove the drillstring from the hole in order to make the necessary measurements obtainable by wireline techniques. In addition to the ability to log the characteristics of the formation through which the drill bit is passing, this information on a real time basis provides substantial safety and logistical advantages for the drilling operation.
One potential problem with MWD logging tools is that the measurements are typically made while the tool is rotating. Since the measurements are made shortly after the drillbit has drilled the borehole, washouts are less of a problem than in wireline logging. Nevertheless, there can be some variations in the spacing between the logging tool and the borehole wall (“standoff”) with azimuth. Nuclear measurements are particularly degraded by large standoffs due to the scattering produced by borehole fluids between the tool and the formation.
U.S. Pat. No. 5,397,893 to Minette, the contents of which are fully incorporated herein by reference, teaches a method for analyzing data from a MWD formation evaluation logging tool which compensates for rotation of the logging tool (along with the rest of the drillstring) during measurement periods. The density measurement is combined with the measurement from a borehole caliper, preferably an acoustic caliper. The acoustic caliper continuously measures the standoff as the tool is rotating around the borehole. If the caliper is aligned with the density source and detectors, this gives a determination of the standoff in front of the detectors at any given time. This information is used to separate the density data into a number of bins based on the amount of standoff. After a pre-set time interval, the density measurement can then be made. The first step in this process is for short space (SS) and long space (LS) densities to be calculated from the data in each bin. Then, these density measurements are combined in a manner that minimizes the total error in the density calculation. This correction is applied using the “spine and ribs” algorithm to give a corrected density.
U.S. Pat. No. 6,584,837 to Kurkoski, fully incorporated by reference herein, discloses a LWD density sensor that includes a gamma ray source and at least two NaI detectors spaced apart from the source for determining measurements indicative of the formation density. A magnetometer on the drill collar measures the relative azimuth of the NaI detectors. An acoustic caliper is used for making standoff measurements of the NaI detectors. Measurements made by the detectors are partitioned into spatial bins defined by standoff and azimuth. Within each azimuthal sector, the density measurements are compensated for standoff to provide a single density measurement for the sector. The azimuthal sectors are combined in such a way as to provide a compensated azimuthal geosteering density. The method of the invention may also be used with neutron porosity logging devices.
MWD instruments, in some cases, include a provision for sending at least some of the subsurface images and measurements acquired to recording equipment at the earth's surface at the time the measurements are made using a telemetry system (i.e. MWD telemetry). One such telemetry system modulates the pressure of a drilling fluid pumped through the drilling assembly to drill the wellbore. The fluid pressure modulation telemetry systems known in the art, however, are limited to transmitting data at a rate of at most only a few bits per second. Because the volume of data measured by the typical image-generating well logging instrument is relatively large, at present, borehole images are generally available only using electrical cable-conveyed instruments, or after an MWD instrument is removed from the wellbore and the contents of an internal storage device, or memory, are retrieved.
Many types of well logging instruments have been adapted to make measurements which can be converted into a visual representation or “image” of the wall of a wellbore drilled through earth formations. Typical instruments for developing images of parameters of interest measurements include density measuring devices, electrical resistivity measuring devices and acoustic reflectance/travel time measuring devices. These instruments measure a property of the earth formations proximate to the wall of the wellbore, or a related property, with respect to azimuthal direction, about a substantial portion of the circumference of the wellbore. The values of the property measured are correlated to both their depth position in the wellbore and to their azimuthal position with respect to some selected reference, such as geographic north or the gravitationally uppermost side of the wellbore. A visual representation is then developed by presenting the values, with respect to their depths and azimuthal orientations, for instance, using a color or gray tone which corresponds to the value of the measured property.
One method known in the art for transmitting image-generating measurements in pressure modulation telemetry is described, for example, in U.S. Pat. No. 5,519,668 to Montaron. This method includes making resistivity measurements at preselected azimuthal orientations, and transmitting the acquired resistivity values to the surface through the pressure modulation telemetry. The method described in the Montaron '668 patent requires synchronization of the resistivity measurements to known rotary orientations of the MWD instrument to be able to decode the image data at the surface without transmitting the corresponding rotary orientations at which the measurements were made.
U.S. Pat. No. 6,405,136 to Li, et al. discloses a method for compressing a frame of data representing parameter values, a time at which each parameter value was recorded, and an orientation of a sensor at the time each parameter value was recorded. Generally the method includes performing a two-dimensional transform on the data in the orientation domain and in a domain related to the recording time. In one embodiment, the method includes calculating a logarithm of each parameter value. In one embodiment, the 2-D transform includes generating a Fourier transform of the logarithm of the parameter values in the azimuthal domain, generating a discrete cosine transform of the transform coefficients in the time domain. This embodiment includes quantizing the coefficients of the Fourier transform and the discrete cosine transform. One embodiment of the method is adapted to transmit resistivity measurements made by an LWD instrument in pressure modulation telemetry so that while-drilling images of a wellbore can be generated. The one embodiment includes encoding the quantized coefficients, error encoding the encoded coefficients, and applying the error encoded coefficients to the pressure modulation telemetry.
Other data compression techniques, for various applications, are described in, for example, U.S. Pat. No. 5,757,852 to Jericevic et al, U.S. Pat. No. 5,684,693 to Li, U.S. Pat. No. 5,191,548 to Balkanski et al, U.S. Pat. No. 5,301,205 to Tsutsui et al, U.S. Pat. No. 5,388,209 to Akagiri, U.S. Pat. No. 5,453,844 to George et al, U.S. Pat. No. 5,610,657 to Zhang, and U.S. Pat. No. 6,049,632 to Cockshott et al. Many prior art data compression techniques are not easily or efficiently applicable to the extremely low bandwidth and very high noise level of the communication methods of the typical MWD pressure modulation telemetry system, and, have not been suitable for image transmission by such telemetry.
There is a need for a method of determining subsurface features in downhole logging data, for example with azimuthal density variations from measurements made by a MWD logging tool. Such a method preferably provides for real-time determination of down hole parameters for communication to the surface, or provides for real time imaging of the subsurface environment during drilling operations. The present invention satisfies this need.